Embodiments of the present disclosure relate generally to the field of drilling and processing of wells. More particularly, present embodiments relate to a system and method for determining the presence of and controlling motion (e.g., rotation) of a drill string in a drilling rig.
During a drilling process, the drill string may be supported and hoisted about the drilling rig by a hoisting system for eventual positioning down hole in a well (e.g., a wellbore). As the drill string is lowered into the well, a drive system may rotate the drill string to facilitate drilling. Further, at the end of the drill string, a bottom hole assembly (BHA) and a drill bit of the BHA may press into the ground to drill the wellbore. Maintaining a desired weight on bit (WOB), which is a desired amount of weight on the drill bit, may enhance the drilling processes. In particular, maintaining a high rate of penetration without damaging the BHA is desired.
In many drilling processes, the wellbore may include vertical and directional segments. For example, the drill string may initially drill a first vertical segment to a desired depth by utilizing the top drive, the weight of the drill string, and/or a mud motor. In order to drill a directional section or segment, the top drive may be stopped from exerting a force on the drill string, but may be used to hold a position of the drill string. The mud motor of the drill bit may then be adjusted to drill a directional segment at a desired angle, e.g., a horizontal segment. Unfortunately, once the drill string is in the directional (e.g., horizontal) segment in particular, and in the vertical segment to an extent, the drill string may be susceptible to resting against or contacting sides of the wellbore, which may increase a frictional force against the drill string, causing the drill string to stick against the sides of the wellbore. As more weight is added to the drill string by lowering a drawworks of the drilling rig, the drill string may break free from the sides of the wellbore and fall into and contact an end of the wellbore, which may overload the drill bit proximate the end of the wellbore.
Thus, drilling the directional (e.g., horizontal) segment in particular, and the vertical segment to an extent, may be enhanced by inducing a rocking motion (e.g, alternating clockwise and counterclockwise rotations about a longitudinal axis of the drill string) in the drill string to reduce frictional forces between the sides of the wellbore and the drill string. The rocking motion may be induced by exerting a torque (e.g., rotation) at a top of the drill string via a top drive disposed on the drilling rig proximate the top of the drill string. Providing torque to the drill string in alternating clockwise and counterclockwise directions about the longitudinal axis, for a certain amount of turns (e.g., a certain amount of 360° rotations) in each direction, may decrease frictional forces between the drill string and the sides of the wellbore, particularly proximate directional (e.g., horizontal) segments, which may reduce a likelihood that the drill string slips.
It should be noted that the amount of rotation applied to the drill string at the top drive generally does not propagate all the way down the drill string. In other words, elasticity of the drill string, among other factors, causes the rotation to “dissipate” as rotation travels down the drill string. Thus, determining how far down the well bore the drill string actually rotates may not be trivial. Further, providing too many turns to the drill string via the top drive may result in adverse effects. For example, providing too many turns to the drill string may result in an undesired altered drilling angle. Conversely, applying too few turns to the drill string may result in inefficient drilling and may increase susceptibility of the drill string to frictionally engage with the wellbore and, ultimately, slip, as previously described. Thus, traditionally, operators have (a) determined a desired location (known as a “neutral point”) on the drill string to which rotation of the drill string is intended to reach, and (b) employed engineering calculations to determine how many turns must be applied via the top drive to reach the neutral point. Unfortunately, such engineering calculations may be estimates, which, when applied, may result in an undesired altered drilling angle and/or slippage of the drill string. Accordingly, it is now recognized that there is a need for improved detection and maintenance of motion (e.g., rotation) of the drill string with respect to WOB.